1. Field of the Invention
The present invention relates generally to well testing and, more particularly, to apparatus and methods for a flowhead assembly for safer well testing operations.
2. Description of the Background
Well testing systems may be utilized to permit test flowing of an oil or gas well, either before or after casing is set, to determine how the well is expected to perform. The type of fluids, rates of flows, build up of pressure after shutting off the flow, temperature, and other measureable factors are very important in predicting how the well will perform should the well be brought into production. Accordingly, the value of the well is more accurately predictable after well testing. With the results of well testing, as well as other information, the well operator is in a much better position to make informed decisions most likely to lead to profitable results.
The piping systems for well testing systems which must connect a downhole formation thousands of feet below the surface to a surface burner and other equipment may comprise hundreds or thousands of different connections. Some of these connections must often be adapted to the particular configuration of a particular well. Obviously, not all connections can be made at once. Therefore, earlier made connections may be subject to stress as subsequent connections are provided. Moreover, the typical repeated application of pressure to the pipe and the release of pressure, or other movement of pipe, during testing may produce stress on the connections. Because the length of the pipe from the formation to be tested and the surface may be one or more miles, the pipe has considerable volume. During a production test, formation fluids flow from the isolated well interval or zone up through the pipe, typically to a master valve, a swivel, into a surface flowhead with multiple inputs/outputs, where it is then directed to measurement related equipment such as one or more heaters, separators, burners, and the like. Measurements are then made of flow rates, temperatures, pressure, and time, as various valves are opened and closed, to determine the production capability of the well.
The test system after assembly must comprise tight seals to prevent leakage of flammable and/or poisonous gas, e.g., hydrogen sulfide. However, the testing structure is large and subject to movement, stress, or variation during assembly and/or operation and/or during emergencies. Any leakage of flammable gases and/or poisonous gases is highly problematic for safety reasons.
Moreover, gases such as hydrogen sulfide may dissolve O-rings. Hydrogen sulfide is heavier than air and tends to sink into lower areas on a ship or drilling rig where it accumulates rather than dissipates into the atmosphere making explosions, fires, and poisoning a hazard. In some cases, whether the gas produced contains hydrogen sulfide or not is unknown prior to testing.
Especially for offshore wells drilled with drill ships or other platforms or rigs, emergencies may occur which require shutting in the well whereby gasses may remain in the pipes. For instance, stormy weather may move in whereby the drill ship is not able to continuously maintain its position and must therefore move off the well. Any gases are preferably retained in the pipe to prevent any dangerous leakage and/or environmental problems.
The following patents show prior art attempts to solve the above and related long known significant problems for which solutions have been diligently sought. However, the following patents do not show the improvements taught hereinafter in accord with the present invention.
U.S. Pat. No. 3,981,188, issued Sep. 21, 1976, to Barrington et al., discloses a method and apparatus for testing wells where extremely high temperatures and pressures are to be encountered in the zone under test. The apparatus provides means for testing and trapping samples of well fluid from the formation in the zone under test for removal from the well bore with substantial reduction in sample pressure at the ground surface. The method permits confining the well fluid under test within the well bore near the zone under test to minimize the possibility of hazardous well fluids reaching the ground surface other than as trapped samples in expandable sampler chambers or otherwise safely controlled.
U.S. Pat. No. 4,253,525, issued Mar. 3, 1981, to David E. Young, discloses a valve system for retaining production fluids in the subsea production pipe upon disconnection of the riser from the subsea wellhead during a production test of an offshore well which includes a normally closed valve releasably connected to a normally open valve. The normally open valve can be hydraulically closed from a remote control station upon disconnection of the riser in order to retain fluids in the production pipe thereabove, and when closed will hold pressure in either longitudinal direction.
U.S. Pat. No. 4,368,871, issued Jan. 18, 1983, to David E. Young, discloses a lubricator valve apparatus adapted for use when running wireline tools into an offshore well during a production test of the well. The valve includes a valve body having a central flow passage and a ball valve element for opening and closing the passage, hydraulically operable means responsive to surface-controlled pressure for opening and closing the ball valve, latch means for releasably holding the ball valve in both the open and the closed positions, and bypass valve means for equalizing pressures across the ball valve prior to opening thereof and arranged in response to pressure applied at the surface to the production pipe to be opened to provide a flow path for well control fluids.
U.S. Pat. No. 4,658,904, issued Apr. 21, 1987, to Doremus et al., discloses a subsea test tree which includes a hydraulically operable control unit and shut-in valve unit that are releasably latched together. The control unit includes an integral retainer valve system at the upper end thereof. The main shut-in valve, which is a ball valve, is a fail-close device under the influence of a spring and nitrogen pressure. Additional assistance in closing the valve may be provided if needed by hydraulic pressure applied to a surface control line. Internal pressure may be vented prior to unlatching the control unit in case of an emergency.
U.S. Pat. No. 4,668,126, issued May 26, 1987, to James A. Burton, discloses a method and apparatus for remotely connecting or disconnecting upper flexible choke/kill lines (including auxiliary lines) to choke/kill lines of a floating drilling rig riser which has been lowered toward the sea floor. Remote stab assemblies are mounted to a stowable tension ring releasably secured to a housing secured to rig beams. In the stowed position, hydraulic stab connectors secured to travelling yoke assemblies are disconnected from each line. The travelling yoke assemblies are moved to an outer position so that the flexible drape hoses clear the space beneath the housing in order that a blowout preventer stack may be trolleyed in from the side of the rig moon pool during running or retrieval. The stack is lowered toward the sea floor by the riser. A telescopic joint is connected to the top of the riser and lowered through the housing and the tension ring. The tension ring is temporarily connected to the telescopic joint, disconnected from the housing and rides down with the telescopic joint while the stack, riser and telescopic joint are lowered until the stack is landed on the sea floor. The tension ring is then partially connected to the telescopic joint as the tension cables are pulled upwardly. Apparatus is provided for angularly and axially aligning the stab connectors with the choke/kill lines of the riser when the travelling yoke assemblies are moved inwardly where complete connection of the tension ring and telescopic joint is accomplished.
U.S. Pat. No. 4,753,292, issued Jun. 28, 1988, to Ringgenberg et al., discloses a method of well testing, including treating, whereby a testing string including a tool bore closure valve is run into the well bore with the valve in an open mode, the string may be automatically filled, a packer may be pressure tested without cycling the tool bore closure valve, and fluids may be spotted into the testing string, displacing wellbore fluids from the bottom of the testing string, prior to running the test.
U.S. Pat. No. 4,790,378, issued Dec. 13, 1988, to Montgomery et al., discloses a well testing apparatus for running on a single-conductor electric cable for gathering reservoir information. The apparatus utilizes two pressure gages and a valve, the valve being landable in a downhole receptacle and being operable to shut in the well or to open it for flow by tensioning or relaxing the electric cable. One of the gages senses well pressures below the valve and the other gage senses pressures above the valve. Both pressure gages send signals to the surface corresponding to the pressures sensed thereby both while the well is shut in and while it is flowing. The pressure signals are processed by surface readout equipment for real-time display, recording and/or printout, the apparatus including, if desired, a temperature sensor which sends appropriate signals to the surface which not only indicate the well temperatures sensed but the temperatures are used by a computer and its software to automatically correct the pressure readings for temperature affects. The apparatus uses well testing methods and electronic toggling and sequencing devices for use in downhole test tools for switching power from instrument to instrument in the test tool string in predetermined sequence in order to receive signals from each such instrument in turn.
U.S. Pat. No. 4,830,107, issued May 16, 1989, to William D. Rumbaugh, discloses a well test tool including a valve lowerable into a well on a flexible line and locked and sealed in a downhole landing receptacle, the valve being openable and closable to permit or prevent flow therethrough. Well pressures below the test tool being sensed and recorded by a recording pressure gage both during periods of flow and during shut-in periods. The recording pressure gage is either carried by the test tool as a part thereof or is supported in the well independent of the test tool. The valve of the test tool is shiftable between open and closed positions by suitable tools lowered into the well on the flexible line. The flexible line and tools are not required in the well during either of the shut-in or flow periods, excepting only during the shifting operation, thus permitting the flexible line to be slacked during such flow or shut-in periods, or removed from the well altogether. In either case, the well test will be unaffected by movement (as by wind, wave, or similar forces) of super craft on which the flexible line reel and equipment, and personnel relating thereto, may be carried.
U.S. Pat. No. 4,848,463, issued Jul. 18, 1989, to Ringgenberg et al., discloses a well testing apparatus which includes a housing having a formation fluid flow passage. A sliding sleeve tester valve is reciprocably disposed in the housing. A probe separable from the housing and constructed to be received coaxially within the sliding sleeve tester valve has a probe passage defined therethrough for communicating the formation fluid flow passage with a measuring device carried on the probe. A probe valve is also disposed in the housing and is constructed to receive a lower end of the probe. A releasable connector operably connects the probe and the sliding sleeve tester valve so that the sliding sleeve tester valve is moved between its open and closed positions in response to reciprocal movement of the probe relative to the housing. The tester valve can be operated an indefinite number of times, and whenever desired the probe can be disconnected from the tester valve in response to an appropriately timed reciprocable motion of the probe.
U.S. Pat. No. 5,379,839, issued Jan. 10, 1995, to Jack Hisaw, discloses a well testing valve for obtaining a pressure build-up survey from a well bore intersecting a reservoir, the well bore containing a landing receptacle. The well testing valve comprises locking means for locking the well testing valve in the landing receptacle, valve means for selectively opening and closing the well bore. Also included is a rotational power source including a control means for selectively opening and closing the well bore, and recording means for recording the bottom hole pressure and temperature.
U.S. Pat. No. 6,209,650B1, issued Apr. 3, 2001, to Ingebrigtsen et al., discloses a subsea well arrangement for offshore production of oil or gas, comprising a wellhead, a christmas tree mounted on the wellhead and at least one riser for connection with a production vessel at the sea surface. At the top of the christmas tree there is provided a swivel device communicating with the christmas tree, and the swivel device is provided with preferably laterally directed connecting members for risers or hoses and for an umbilical or control cable.
U.S. Pat. No. 6,223,825B1, issued May 1, 2001, to Ingebrigtsen et al., discloses a swivel assembly for installation at a well for subsea production of oil or gas and adapted to be connected to a production vessel at the sea surface. The swivel assembly comprises a main fluid swivel having at least two paths and an electric/hydraulic auxiliary swivel for signal communication and power transfer. The fluid swivel is provided with a rotatable swivel housing at the top of a stationary christmas tree, preferably comprising a small number of valves, such as a production master valve and an annulus master valve. The paths are through-running vertically in the central core member of the fluid swivel so as to make possible well intervention from the upper side of the fluid swivel.
U.S. Pat. No. 6,497,286B1, issued Dec. 24, 2002, to Hans Paul Hopper, discloses an underwater well system in which an initially vertical drilling riser conduit is fixed by a template at the seabed in a non-vertical orientation. Drilling is carried out through wellhead in the template which also includes a valve tree allowing the production fluid to be brought to the surface along a line separate from the drilling riser conduit. The template may be a junction template allowing several wells to be drilled from a single template, or allowing the template to be connected by one or more drilling conduits to further templates such that a wide area of the seabed can be covered for a single drilling riser conduit.
U.S. Pat. No. Re. 29,562, reissued Mar. 7, 1978, to Wray et al., discloses a method and apparatus for testing offshore wells where variations in well annulus pressure are utilized to control the valving operation of a testing tool and entrap a formation sample. A confined body of pressurized fluid positioned in a testing string is utilized to predetermine the annulus pressure changes which will effect said valving and sample entrapping operations.
Those skilled in the art have long sought and will appreciate the present invention which addresses these and other problems.